Pine Cliff Energy Ltd. Announces Fourth Quarter and Annual Results
TSX - Toronto Stock Exchange
CALGARY, March 23 /CNW/ - Pine Cliff Energy Ltd. (www.pinecliffenergy.com) (TSX VENTURE: PNE) is pleased to announce its financial and operational results for the three months and fiscal year ended December 31, 2005.
HIGHLIGHTS
Operations
The Company's future operating philosophy will be to conduct exploration and development programs in Canada and internationally that are rated as low risk ventures, but will also proceed with activities in both areas that are in higher risk and potentially higher return categories. At the present time most of Pine Cliff's activities are being managed by a consulting contract with its former parent, Bonterra Energy Income Trust. Pine Cliff is presently in the process of hiring people to perform most of its technical requirements. The Company is optimistic with regard to the properties it will be exploring and developing in 2006.
Financial
Revenue from petroleum and natural gas sales for the year was $633,873. The fourth quarter sales figure was $372,315 accounting for 58.7 percent of the 2005 total figure. The Company experienced a loss in 2005 which is totally attributable to an asset write down of $588,256 in the fourth quarter for its Auburndale property. Pine Cliff's working capital at December 31, 2005 was $3,565,689. This working capital and the Company's 2006 cash flow should be sufficient to finance the capital expenditures for 2006.
RESERVES
The Company engaged the services of Sproule Associates Limited to prepare a reserve evaluation with an effective date of December 31, 2005. The reserves are located in the Province of Alberta. The majority of the Company's production is comprised of natural gas. The Company's main gas producing area is located in the Sundance area of West Central Alberta. The gross reserve figure in the following charts represents the Company's ownership interest before royalties and the net figure is after deductions for royalties.
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SUMMARY OF OIL AND GAS RESERVES AS OF DECEMBER 31, 2005 FORECAST PRICES AND COSTS
RESERVES Natural Natural Gas Gas Liquids Gross Net Gross Net RESERVE CATEGORY (MMcf) (MMcf) (Mbbl) (Mbbl) PROVED Developed Producing 352 283 13.3 9.0 TOTAL PROVED 352 283 13.3 9.0 PROBABLE 216 167 8.1 5.6 TOTAL PROVED PLUS PROBABLE 568 450 21.4 14.6
RECONCILIATION OF TRUST GROSS RESERVES BY PRINCIPAL PRODUCT TYPE (FORECAST PRICES AND COSTS)
Natural Gas
Gross Gross Gross Proved Probable Proved (MMcf) (MMcf) Plus Probable (MMcf) December 31, 2004 - - - Extension 288 100 388 Improved recovery - 58 58 Technical revisions 32 (24) 8 Discoveries - - - Acquisitions 52 82 134 Economic factors - - - Production (20) - (20) December 31, 2005 352 216 568
SUMMARY OF NET PRESENT VALUES OF FUTURE NET REVENUE AS OF DECEMBER 31, 2005 FORECAST PRICES AND COSTS
NET PRESENT VALUE OF FUTURE NET REVENUE After Income Taxes Discounted at (%/year) 0 5 10 15 20 (M$) RESERVE CATEGORY PROVED Developed Producing 2,686 2,460 2,277 2,126 1,999 TOTAL PROVED 2,686 2,460 2,277 2,126 1,999 PROBABLE 1,132 902 745 633 549 TOTAL PROVED PLUS PROBABLE 3,818 3,362 3,022 2,759 2,548
Year Edmonton Alberta Gas Propane Butane Pentane Par Reference Price Price Plantgate (Cdn $ (Cdn $ (Cdn $ (Cdn $ (Cdn $ per barrel) per MCF) per barrel) per barrel) per barrel) 2006 70.07 11.37 39.25 47.01 71.77 2007 70.99 10.63 39.76 47.62 72.71 2008 62.73 8.76 35.14 42.08 64.25 2009 57.53 7.69 32.22 38.59 58.92 2010 54.65 7.39 30.61 36.66 55.97 2011 55.47 7.52 31.07 37.21 56.81 2012 56.31 7.63 31.54 37.77 57.67 2013 57.16 7.77 32.01 38.34 58.54 2014 58.02 7.90 32.50 38.92 59.42 2015 58.89 8.04 32.99 39.51 60.31 2016 59.78 8.18 33.48 40.10 61.22
Natural gas and liquid prices escalate at various rates thereafter.
The following cautionary statements are specifically required by NI 51-101.
It should not be assumed that the estimates of future net revenue presented in the above tables represent the fair market value of the reserves. There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material. Disclosure provided herein in respect of BOE's may be misleading, particularly if used in isolation. In accordance with NI 51-101, a BOE conversion ratio of 6mcf:1bbl has been used in all cases in this disclosure. This BOE conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Estimates of reserves and future net revenues for individual properties may not reflect the same confidence level as estimates of reserves and future net revenues for all properties due to the effects of aggregation.
FINANCIAL AND OPERATIONAL SUMMARY
Quarterly Financial and Operational Highlights
2005 4th 3rd 2nd 1st Revenue - oil and gas $ 372,315 $ 121,141 $ 140,417 $ - Funds Flow from Operations(1) 275,942 68,119 48,374 (24,176) Per Share Basic 0.01 0.00 0.00 (0.00) Per Share Diluted 0.01 0.00 0.00 (0.00) Net (Loss) Earnings (223,241) (37,092) (44,553) (24,176) Per Share Basic (0.01) (0.00) (0.00) (0.00) Per Share Diluted (0.01) (0.00) (0.00) (0.00) Capital Expenditures and Acquisitions 160,809 321,206 1,615,915 - Total Assets 5,267,988 5,609,386 5,481,085 192,458 Working Capital (Deficiency) 3,565,689 3,450,555 3,513,801 (185,983) Shareholder's Equity 5,110,407 5,305,042 5,308,028 (24,175) Operations Oil and Liquids (barrels per day) 8 4 6 - Natural Gas (MCF per day) 279 116 153 -
(1) Funds flow from operations is not a recognized measure under GAAP. Management believes that in addition to net earnings, funds flow from operations is a useful supplemental measure as it demonstrates the Company's ability to generate the cash necessary to fund future growth through capital investment. Investors are cautioned, however, that this measure should not be construed as an indication of the Company's performance. The Company's method of calculating this measure may differ from other issuers and accordingly, it may not be comparable to that used by other issuers. For these purposes, the Company defines funds flow from operations as funds provided by operations before changes in non-cash operating working capital items.
The Company was incorporated in the Province of Alberta on November 10, 2004 and commenced operations on April 8, 2005. The Company did not have operations as of December 31, 2004 and therefore is only presenting quarterly statements for the year ended December 31, 2005. The Company had no income or expenditures to be recognized in an income statement and had no cash transactions to December 31, 2004.
Production
On April 8, 2005, with an effective date of January 1, 2005, the Company acquired interests in two natural gas properties for $999,701. The Sundance land, located in West Central Alberta was the major property acquired. Pine Cliff now has a 13.2 percent working interest (subject to crown royalty) in 4,320 acres in this area. There are two wells (0.308 net) on these lands that have been producing for approximately two years. Two additional multi-zone wells were drilled in 2005 (net .2). Production commenced in April at one location (net .038) and in October for the other location (net .15). In 2005 production from this area averaged 175 MCF of natural gas and seven barrels of natural gas liquids per day. In December 2005 daily production rates from the Sundance property was 349 Mcf and 10 barrels of natural gas liquids. Pine Cliff also acquired a 100 percent interest in a 256 hectare Crown lease in the Auburndale area of East Central Alberta. The Company drilled a Devonian well for sweet natural gas during the second quarter. The Company has tested this well and has concluded that the projected production volume is not sufficient to construct a five kilometer pipeline to tie it in. The drilling and land costs have been written off in 2005 (see Write-down of Asset).
Revenue
Revenue from petroleum and natural gas sales for the year was $633,873. This includes $372,315 for the fourth quarter. This is an increase of $251,174 from the third quarter. The increase was due to higher commodity prices and commencement of production in October from the new Sundance well. Average price received in 2005 for its natural gas was $10.78 per MCF and $62.42 per barrel for natural gas liquids. The Company did not have hedging agreements in 2005 and presently does not have any future hedging agreements.
Royalties
Royalties consist of Crown royalties ($17,464) paid to the Province of Alberta and gross overriding royalties ($21,366). The Company receives a partial rebate (currently 25%) from royalties paid to the Province of Alberta. The Company received a royalty holiday on a portion of its new production.
Interest Income
The Company maintains an investment account with its principal banker that pays interest at prime less 2.25 percent as long as the Company maintains a minimum balance of $1,500,000.
Production Costs
Production costs for the year ended December 31, 2005 were $53,449 or $5.41 per BOE (Q4 - $4.37 per BOE, Q3 - $9.51 per BOE and Q2 - $7.37 per BOE). BOE's are calculated using a conversion ratio of 6 MCF to 1 barrel of oil. The conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead and as such may be misleading if used in isolation. Lower production costs from the natural gas well that commenced production in the fourth quarter was the main reason for the decline in costs per BOE from Q3.
General and Administrative
Pine Cliff does not have any employees at the present time but has engaged the services of a geologist on a consulting basis during the third quarter of 2005. Effective February 1, 2005, Pine Cliff entered into a management agreement with Comstate Resources Ltd. ("Comstate"), a wholly owned subsidiary of Bonterra Energy Income Trust and a company with common directors and management, to have Comstate provide executive services (President and CEO, CFO and COO), accounting services, oil and gas administration and office administration. The management fee consists of a monthly fee of $12,000 ($18,000 effective January 1, 2006), three percent of net earnings before income taxes, plus out of pocket costs. Total fees for the year ended December 31, 2005 were $132,000 plus minimal out of pocket costs. The majority of the remaining general and administrative expenses consist of $44,160 for geological consulting, accounting and legal costs of $19,453 associated with continuous disclosure requirements and general start up costs of $16,458.
Stock Based Compensation
The Company has a stock-based compensation plan. The Company records a compensation expense over the vesting period based on the fair value of options granted to employees, directors and consultants. In the second quarter the Company issued 1,732,000 stock options with the fair value estimated using the Black-Scholes option pricing model, assuming a weighted risk free interest rate of 3.5 percent, expected weighted average volatility of 88 percent, expected weighted average life of 3.5 years and no annual dividend rate. The total expense to be amortized over the vesting period of the options is $136,536 of which $29,049 (Q3 - $29,806, Q2 - $28,186) was expensed in the fourth quarter.
Write-down of Asset
The Company drilled a Devonian gas well in the second quarter of 2005. The well, although capable of production, does not contain sufficient reserves to warrant a five kilometer pipeline. Given the lack of current economics for this well, no proved or probable reserves were assigned to the well in the preparation of the third party engineering report. With the Company following the successful efforts method of accounting (see below), capital costs associated with each field that are in excess of that fields economic value are to be written off. As such the Company wrote off $588,256 in respect of the cost of the land and development costs incurred in drilling the Devonian well.
Depletion, Depreciation and Amortization
The Company follows the successful efforts method of accounting for petroleum and natural gas properties and related equipment. Costs of acquiring unproved properties are capitalized. When petroleum and natural gas properties are found to contain proved reserves as determined by Company engineers, the related net book value is depleted on the unit-of-production basis, calculated by field. The costs of dry holes and abandoned properties are charged to operations. Geological costs, lease rentals and carrying costs are charged to income as incurred. Costs of drilling exploratory and development wells that result in additions to proved reserves are capitalized and depleted on the unit-of-production basis. Tangible equipment is depreciated on a straight-line basis over ten years. Provisions are made for asset retirement obligations through the recognition of the fair value of obligations associated with the retirement of tangible long-life assets being recorded in the period the asset is put into use, with a corresponding increase to the carrying amount of the related asset. The obligations recognized are statutory, contractual or legal obligations. The liability is adjusted over time for changes in the value of the liability through accretion charges which are included in depletion, depreciation and accretion expense. The costs capitalized to the related assets are amortized to earnings in a manner consistent with the depletion and depreciation of the underlying asset. At December 31, 2005, the estimated total undiscounted amount required to settle the asset retirement obligations was $42,796.
Income Taxes
The Company follows the liability method of accounting for income taxes under which the income tax provision is based on the temporary differences in the accounts calculated using income tax rates expected to apply in the year in which the temporary differences will reverse. The Company has sufficient tax pools so it is not liable for current income tax in 2005. Should the Company not incur additional exploration and development expenditure in 2006, based on current pricing, the Company may be taxable in 2006. The Company has the following tax pools which can be used to reduce future taxable income:
Rate of Utilization % Amount Undepreciated capital costs 25 $ 216,298 Canadian oil and gas expenditures 10 809,254 Canadian development expenditures 30 392,275 Canadian exploration expenditures 100 387,062 Share issue costs 20 134,118 $ 1,939,007
Net Loss
The net loss in the fourth quarter of $223,241 (Q3 - $37,092, Q2 - $44,553, and Q1 - $24,176) was primarily due to the write-down of the Auburndale property ($588,256). Excluding the write-down, the Company had pre-tax profits of $234,540 in the fourth quarter. The Company is optimistic that current planned activity will result in improved results in the future.
Liquidity and Capital Resources
As of December 31, 2005, Pine Cliff had positive working capital of $3,565,689. These funds will be used to fund future development of existing properties and to acquire additional oil and gas properties. Subsequent to year-end, the Company incorporated a 93 percent owned subsidiary CanAmericas Energy Ltd. (CanAmericas) to carry on exploration and development work in South America. The Company funded CanAmericas with an equity injection of $1.4 million US. The Company is authorized to issue an unlimited number of common shares without nominal or par value. Equity transactions during the past nine months are as follows:
Shares Amount Balance, December 31, 2004 10 $ 1 Issued pursuant to public offering 36,420,031 5,463,005 Share issue costs - (167,647) Future tax adjustment on share issue costs - 57,069 Balance, December 31, 2005 36,420,041 $ 5,352,428
On April 7, 2005, the Company concluded its initial public offering of 36,420,031 Common Shares at $0.15 per share for gross proceeds of $5,463,005. Total expenses related to the initial public offering were $167,647. The Company granted 930,000 stock options to its directors and officers, and an additional 802,000 stock options to other service providers at an exercise price of $0.15 per share. The Company commenced trading on the TSX Venture Exchange on April 11, 2005. A summary of the status of the Company's stock option plan as of December 31, 2005 and December 31, 2004, and changes during the twelve months and from incorporation periods ending on those dates is presented below:
December 31, 2005 December 31, 2004 Options Weighted- Options Weighted- Average Average Exercise Price Exercise Price Outstanding at beginning of period - $0.00 - $0.00 Options granted 1,752,000 0.16 - 0.00 Options cancelled (66,000) 0.15 - 0.00 Outstanding at end of period 1,686,000 $0.16 - $0.00 Options exercisable at end of period - $0.00 - $0.00
Of the 1,686,000 options that are outstanding as of December 31, 2005, 1,666,000 are exercisable 50 percent on April 5, 2006 and the remaining 50 percent on April 5, 2007. The options all expire on January 31, 2010.
Forward-Looking Information Certain information set forth in this document, including management's assessment of Bonterra Energy Income Trust's ("the Trust" or "Bonterra") future plans and operations, contains forward-looking statements. By their nature, forward-looking statements are subject to numerous risks and uncertainties, some of which are beyond Bonterra's control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Bonterra's actual results, performance or achievement could differ materially from those expressed in, or implied by these forward-looking statements, and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Bonterra will derive therefrom. Bonterra disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Readers are cautioned that net present value of reserves does not represent fair market value of reserves.
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